康菲 (COP) 2011 Q4 法說會逐字稿

Welcome to the fourth quarter ConocoPhillips earnings conference call.

My name is Kim and I will be your operator for today's call.

At this time, all participants are in a listen-only mode.

Later, we will conduct a question-and answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr.

Clayton Reasor, Vice President of Corporate and Investor Relations.

Mr.

Reasor, you may begin.

Great.

Good morning.

Welcome to ConocoPhillips's fourth quarter earnings conference call.

We appreciate your interest in our company.

I'm joined today by Jeff Sheets, Senior Vice President of Finance and our CFO.

This morning, we will provide a summary of our key financial and operating results for the fourth quarter, as well as our outlook for 2012.

As in the past, you can find our presentation material on the Investor Relations section of ConocoPhillips' website.

Please take a look at the Safe Harbor statement that we have on the bottom of this slide.

It's a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session, and actual results may be materially different from what's presented today.

And factors that could cause actual results to differ are included here, as well as in our filings with the SEC.

So with that, I'll turn the call over to Jeff Sheets to take you through our fourth quarter results.

Jeff?

Thanks, Clayton.

I'll start with an overview of our fourth quarter which is on slide 2.

During the quarter, our earnings, adjusted for special items, were $2.7 billion, or $2.02 a share.

That's up from $1.9 billion or $1.32 a share, in the fourth quarter of last year.

Our annualized return on capital employed was 13%.

We generated cash from operations of $5.8 billion, which is $4.39 per share.

In E&P, our production of 1.6 million BOE per day was higher than the prior quarter and slightly above our expectations.

In R&M, our global refining capacity utilization rate was 94%.

We made significant progress on our asset disposition program with the sale of the Colonial Seaway Crude and Seaway Products pipelines for $2.4 billion in proceeds during the quarter.

Our repurchase of 46 million shares this quarter represented 3% of our shares outstanding.

And we ended the year with $6.4 billion in cash and short-term investments.

So I'll turn to slide 3 and talk about those earnings in more detail.

Reported earnings for the quarter were $3.4 billion, which included $723 million of special items.

Special items included $1.5 billion in net gains from asset sales, largely resulting from the pipeline dispositions I just mentioned.

We also had $649 million of impairments.

The large impairments included $395 million related to our investment in the Naryanmarneftegaz joint venture in Russia and $190 million for certain conventional natural gas properties in Canada.

Other special items in Q4 included $101 million in settlement and other costs related to the Bohai Bay incident, and $25 million related to our repositioning efforts.

Taking these special items into account, adjusted earnings were $2.7 billion, which is about $750 million higher than the fourth quarter of 2010.

Our E&P segment improved by around $500 million, primarily due to stronger crude oil and LNG prices, offset by higher taxes.

R&M's fourth quarter adjusted earnings of $200 million were basically unchanged from a year ago.

And combined, our other segments contributed about $250 million to the increase in earnings this quarter, and we'll go through more detail on that on some subsequent slides.

So let's go to slide 4 and look at our 2011 full-year earnings.

The full-year 2011 adjusted earnings were $12 billion, which were more than $3 billion improved from 2010.

All of our business segments generated better financial results in 2011 than in 2010.

So excluding the LUKOIL segment, for which we stopped recording equity earnings in the fourth quarter of 2010, and which had $1.25 billion of earnings in Q4 2010, our adjusted earnings increased by $4.6 billion from 2010 to 2011.

So next we will go through some detail on our segment earnings, and we will start with the production levels in our Upstream business, which are highlighted on slide 5.

Fourth quarter production was 1.6 million BOE per day.

That is down 8% compared to the fourth quarter last year.

If you exclude the impact of dispositions and the suspension of our operations in China and Libya, production was down 1% over this time period.

Asset dispositions reduced production by about 30,000 BOE per day; 14,000 or so of that was from North America natural gas production.

In Libya, production was down 43,000 BOE per day, compared to the same period last year.

Production in Libya started again in late November, and continues to ramp up and current production levels are around 20,000 BOE per day.

In Russia, we continue to have difficulties with the reservoir in the YK Field, and our production was down 23,000 BOE per day in that area.

In Bohai Bay, our production was 38,000 BOE per day, lower than a year ago.

ConocoPhillips continued the de-pressurization plan for the field and continues to work with our co-venture and regulatory agencies related to Bohai Bay.

So excluding these items I just discussed, increases in production from exploitation drilling, well performance, and production from major projects offset decreases associated with decline and downtime.

So, some things to note -- compared to the same period last year, fourth quarter production highlights included a 44,000 BOE per day increase in production from our Lower 48 liquids-rich shale plays at Eagle Ford and the Barnett; 32,000 BOE per day increase from Qatargas 3 project; and a 13,000 BOE per day increase associated with new wells at our FCCL joint venture from the Christina Lake Phase C ramp-up.

So we will see similar drivers when we look at our full-year production numbers on slide 6.

For the full year 2011, production was 1.62 million BOE per day, which is down 8% from 2010.

Excluding the impacts of dispositions and Libya and China, production was down 2%, or about 30,000 BOE per day.

Asset dispositions for the year reduced production by 48,000 BOE per day, 17,000 of which was North American natural gas production.

Libya production was down 39,000 BOE per day and production out of Russia was down 23,000 BOE per day, compared to the same period last year.

And the full-year impact of reduced production at Bohai Bay was 15,000 BOE per day.

Like the fourth quarter numbers, 2011 project and drilling performance highlights included significant increases at QG3 and in our North American unconventional plays; and these increases largely offset declines in the rest of our portfolio.

So now, I'll turn to E&P earnings, which is on slide 7.

Adjusted E&P earnings for the quarter were $2.3 billion.

This is 27% higher than the fourth quarter last year.

This increase was primarily driven by higher crude and NGL prices.

And these prices drove both our US and our international adjusted earnings higher.

Our earnings in the fourth quarter reflected a $3.50 Henry Hub natural gas price.

In addition to price impact, lower DD&A, and favorable FX impacts increased earnings this quarter compared to the fourth quarter of 2010.

Adjusted earnings were negatively impacted this quarter versus a year ago by lower sales volumes and higher costs.

Costs were higher, primarily due to the UK tax law change and the fact that the QG3 project was fully online.

So next I will move to slide 8 and talk about some of our E&P unit metrics.

Our cash and income per BOE metrics were better than a year ago and better than the third quarter.

For the year, income per BOE was $15.72, which is improved over $10.56 in 2010.

Full-year cash margins increased from $23.22 to $27.46 in 2011.

This improvement largely reflects the increase in commodity prices, but there's also a small margin enhancement related to changes in our production mix.

And we'll continue to focus on improving margins by shifting our portfolio to a higher margin production as we go forward.

So next let's look at R&M earnings on slide 9.

R&M adjusted earnings of $200 million were basically flat with the fourth quarter last year.

So R&M saw offsetting impacts to earnings this quarter.

Refining margins were lower, and that was offset by lower costs and higher volumes and higher marketing margins.

And with the exception of the Mid-Continent area, the Refining market environment in the fourth quarter was generally worse than the Refining market we saw in the fourth quarter 2010.

This quarter, our Refining margins benefited by approximately $180 million, related to the impact of liquidating inventory associated with the portfolio changes we made during 2011.

As compared to the fourth quarter 2010, our volumes were a benefit to earnings, as global utilization rates were 94%.

And costs related to turn-arounds were $90 million pre-tax during the fourth quarter, which is $117 million less than the same period a year earlier; and utility costs were also lower, primarily as a result of lower natural gas prices.

So if you look at the full year 2011, R&M generated $2.6 billion in adjusted earnings, and $4.1 billion in operating cash flow.

So we'll look at R&M unit metrics on slide 10.

The per-barrel metrics for Refining and Marketing were similar to a year ago and down significantly from the third quarter this year.

The fourth quarter income per BOE was $0.70 and the cash contribution was $1.50.

For the year, income margins of $2.29 per BOE were improved over 2011 margins of $1.10 per BOE.

We continue to look for ways to improve our margins through processing more advantaged crudes and increasing our clean product yield.

An example of this is the Wood River refinery, where at current market prices we expect about a $4.00 per barrel uplift in Wood River's margins as a result of the CORE Project startup in November of this year.

We will take a look at the results of our other operating segments on slide 11.

Adjusted earnings increased in both our chemicals and our midstream segments.

Chemicals earnings of $156 million improved, primarily as a result of higher volumes from international projects.

2011 earnings in this segment were $745 million, up from $498 million in 2010.

Midstream earnings increased $27 million, up to $118 million, in 2011.

In the fourth quarter of 2011, reflecting improvements in NGL prices.

2011 midstream earnings for the year were $458 million, up from $306 million in 2010.

Adjusted corporate expenses were $154 million this quarter.

This was lower than expected, due to favorable foreign exchange impacts, higher capitalized interest, and lower interest expense.

So now, we'll move to talk about cash flow on slide 12.

In the fourth quarter, we generated $5.8 billion in cash from operations, which includes a billion dollars due to a decrease in working capital.

Also during the quarter, we closed several asset dispositions, resulting in proceeds of $2.7 billion.

During the fourth quarter, we funded a $4 billion capital program, $3.5 billion of which was directed towards E&P.

We also paid $4 billion in shareholder distributions, split between $3.1 billion in share repurchases and $900 million in dividends.

This quarter we also reduced debt by $527 million, through the retirement of some notes that matured; and we ended the year with $5.8 billion in cash and $600 million in short-term investments.

So that is looking at our fourth quarter cash flow.

What we will do on slide 13 is look at our full-year sources and use of the cash.

So if you look at all of 2011, we generated $24 billion between cash from operations, asset dispositions and the sale of our LUKOIL shares; and we reduced our cash and short-term investment position by $4 billion.

The cash from operations number of $19.6 billion in 2011 was $2.6 billion higher than the cash from operations in 2010.

So the cash from operations funded a capital program of $14 billion, as well as our dividend of $3.6 billion.

Our asset dispositions of $4.8 billion in 2011 included $1.2 billion from our sale of our remaining interest in LUKOIL, and these proceeds, along with cash from our previous asset sales, largely funded the $11 billion share repurchase program.

And during the year, we also reduced debt by $969 million.

So we'll turn to slide 14 and look at our capital structure.

At the end of 2011, our equity was down $3 billion compared to the end of 2010, largely as a result of our share repurchase program.

Our debt balance was $22.6 billion, which was down a billion dollars from the end of 2010; so it left our debt-to-capital ratio at 26% for the year.

So next we'll move to slide 15 and talk about some capital efficiency metrics.

2011 return on capital employed is 14%, which is up from the 2010 ROCE number of 10%; and our cash return in 2011 was 23%, versus 20% in 2010.

The year-over-year improvements in ROCE were primarily driven by increased improved liquids prices and stronger refining margins, as well as lower capital employed as a result of our share repurchase program.

So looking at ROCEs on a segment level, E&P ROCE improved from 12% to 16%; while R&M ROCE improved from 5% to 13%.

The Chemical segment had a 2011 ROC of 29%, which is up from 22% last year; and Midstream was 57% in 2011, up from 34% in 2010.

So that completes the review of our fourth quarter 2011 results, and I'd like to next move and give you an update on our 2010 through 2012 repositioning efforts.

So, in late 2009, we laid out plans to reposition ConocoPhillips.

We've made significant progress on these initiatives and planned to largely finish those in 2012.

We've made changes to our portfolio in the past two years, with $10.7 billion in asset sales and $9.5 billion of proceeds from our sale of our 20% interest in LUKOIL.

Additionally, we've reduced the refining capacity by about 500,000 barrels per day since the end of 2009.

And we expect to continue an asset sales program of $5 billion to $10 billion during 2012.

We continue to progress our plans to create two leading energy companies.

And with we updated the Phillips 66 Form 10 in January and the distribution of the Phillips 66 shares, and the completion of that transaction is expected to occur in the second quarter of 2012, possibly as early as May.

Another key part of our three-year plan is enhancing returns.

As I just discussed, our returns improved significantly over this time period; and we continue to focus our capital on higher-margin production to help drive margins and returns higher.

We've also focused on improving our financial flexibility and we've reduced debt by $6 billion over the last two years.

The company is in good financial position today, with debt-to-cap at 26%, and cash and short-term investments of $6 billion.

And we've grown shareholder distributions with $15 billion in share repurchases in 2010 and 2011, with an additional $5 billion to $10 billion planned for 2012, as we continue to execute the asset sales program.

And we remain committed to maintaining a competitive dividend that increases annually.

So we've outlined our plans, and you can turn to slide 17 and see some of the impact that, that has on some of our per share metrics.

If you look at slide 17, you see our reserves per share increased 12% from 2010 to 2011; went from 5.7 BOE per share in 2010 to 6.4 BOE per share in 2011.

And our production per share, when you adjust for the impact of the events in Libya, increased 5% from 2010 to 2011; and we expect that that will increase this year by another 3% to 5%.

So I'll wrap up with some forward-looking comments before we open up the line to questions.

Some guidance for 2012, starting with our R&M business.

We expect turn-around activity to be about $450 million pre-tax, with about 40% of that activity occurring in the first quarter 2012; and global refining capacity utilization is expected to be in the low 90s in 2012.

In E&P, we expect 2012 production to be about 1.6 million BOE per day, excluding the impact of any additional asset sales; and the guidance we would give around the impact of additional asset sales is that could reduce production by 50,000 BOE to 100,000 BOE per day.

And this production guidance assumes that we have some restoration of our production in Libya and Bohai Bay.

As we announced earlier this week, we had 2011 organic reserve replacement of 120%.

Of the organic reserves we added last year, less than 10% were from natural gas in the Lower 48 and Canada.

We'll report our F&D costs when we file our 10-K in late February, but we expect those to be in the $15 to $20 per BOE range.

As we previously indicated, our capital budget for 2012 is $15.5 billion, and 90% of this will be directed towards E&P.

We expect our 2012 exploration expenses to be around $1.2 billion, and I'll make a few comments about our progress in developing our exploration portfolio in some core areas.

First, in Australia, we have plans to commence a 5- to 7-well appraisal program around the Poseidon discovery later this quarter.

In Angola, we have officially received our operating licenses for blocks 36 and 37, and we have committed to a seismic program that is going to begin this quarter.

In the Gulf of Mexico, we participated in the recent deep water lease sale, where ConocoPhillips was the successful bidder representing an expenditure of about $157 million net for 75 blocks in the Paleogene play.

And we continue to pursue high-quality liquids-rich unconventional opportunities.

In 2011, we added 500,000 acres in North America shale plays in areas that include the Avalon, the Wolfcamp, and the Niobrara in the Lower 48; and the Duvernay and the Canol in Canada.

In the Caspian, we expect to spud the Nursultan well later this quarter.

So now I'll shift to our progress in growing our liquids-rich shale business in North America.

That's the Eagle Ford, the Bakken, the Permian, and the Cardian plays.

First, at Eagle Ford, we are currently running 16 rigs in the play.

We expect to maintain a 16-rig count average and drill about 180 wells in 2012.

Production in late December was around 50,000 BOE per day, and we continue to see some impacts from curtailments related to infrastructure constraints as a result of the higher well volumes and the increasing liquid content, and just our ongoing development activity.

We would anticipate that average production from the Eagle Ford should grow to around 100,000 BOE per day by the end of 2012.

In the Permian and the Bakken, we are running a total of 10 rigs, and expect to increase this by as much as 50% during 2012.

Fourth quarter production at the Permian and Bakken averaged 50,000 BOE per day and 18,000 BOE per day, respectively.

The Permian activities are focused around the Avalon, the Wolfberry, and the Wolfcamp; and we're using both horizontal and vertical drilling techniques there.

So in addition to our efforts on shale, we're progressing major projects globally.

During the quarter, the APLNG joint venture announced two sales agreements that complete the marketing of APLNG second train.

With the sanctioning of this train, construction's expected during the first quarter of 2012.

In conjunction with this LNG sale to Sinopec, joint venture partner's also agreed to terms which will allow Sinopec to raise their equity interest in the project from 15% to 25%.

In the North Sea, the development of our Jasmine field's under way, with startup expected later this year.

We expect peak production rates of around 34,000 BOE per day in 2013 from that development.

Our Ekofisk South and Eldfisk II projects continue to progress; and production from both of these projects are expected in 2013 and 2014, respectively.

The Wood River CORE Project started operations in mid-November.

And it's resulting in a 5% increase in the clean product yield at that refinery.

Our Chemicals joint venture plans to build a world-scale 1.5 million metric ton per year ethylene cracker and two 500,000 metric ton per year polyethylene units near its existing Cedar Bayou facility, or near a site near the CPChem Sweeny facility in Old Ocean, Texas.

And the estimated project completion date for these would be 2017.

And our Midstream joint venture has several growth projects under way.

These include developments in Niobrara, Permian, Eagle Ford, and the Granite Wash plays, along with logistic opportunities in the Mid-Continent area.

And finally, a couple of items from the corporate perspective -- 2012 DD&A is estimated to be similar to what we saw in the fourth quarter this year.

And corporate expenses in 2012 are expected to be around a billion dollars on an annual basis, excluding any one-time impacts related to the repositioning efforts.

So that concludes the prepared remarks.

So we're ready to open up the line for questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

At this time, we have a question from Argun Murti from Goldman Sachs.

Please go ahead.

Thank you.

A couple of domestic production questions.

You've had very good sequential growth in your Lower 48 liquids production.

It looks like throughout this year, 10,000 to 14,000 barrels a day quarter-on-quarter growth.

Jeff, you mentioned that some of that is working through the backlog, though there's still a little bit of a backlog.

How can we think about these numbers over the course of 2012?

You've got a big ramp up in the Eagle Ford coming.

You mentioned the Permian and the Bakken.

Are these the types of sequential growth rates that are doable in your Lower 48 liquids business?

Yes, maybe just to talk about Eagle Ford.

As we mentioned, we see Eagle Ford as going from we think 50,000 a day to around 100,000 at the end of 2012.

We probably had around 10,000 BOE per day that 's held back because of infrastructure constraints.

And that number used to be like a 30,000kind of number, if I'm remembering correctly in terms of backlog production?

It comes and goes.

As we commented, as Eagle Ford continues to ramp up, we'll be probably working with infrastructure constraints on through this year and on into 2013.

I think once we get beyond the 2013, we feel like the infrastructure constraints will be largely behind us.

So if you just looked at Eagle Ford, and the Bakken, and the Permian, maybe those, our fourth quarter production from those areas was around 116,000 BOE per day.

And that was right at 50,000 out of Eagle Ford, 18,000 out of Bakken, and 15,000 out of the Permian.

We'll see that over time, that those are going to grow to where they get to be in the 2013 to 2015 time period over 250,000 to maybe 275,000 BOE per day.

And it is going to just increase fairly steadily over that time period.

That's great.

Conversely, on the gas side, obviously very low gas prices.

Right.

Can you talk about where your gas rig count was in 2011 or where it ended the year, whatever metric you have, where it is going, in 2012?

And then, what you think that means in terms of what happens to your Lower 48 gas volumes in 2012?

Thank you very much.

Yes, I think our Lower 48 gas volumes will continue to decline.

I think we've got one rig running at LOBO which is primarily gas.

San Juan's some liquids with it, but we've got four rigs running there.

So of the 35 to 40 rigs in the Lower 48, less than 5 of them are really pointing toward gas.

Right.

And I don't think we've got much capital in 2012 allocated towards new gas drilling.

Now if you look at gas drilling, it is in the few hundreds of millions of dollars of our capital program that is addressed towards gas drilling and even that level of expenditure, given the more recent developments of natural gas, pricing is something that we're looking pretty closely at.

So would a high-single digit decline rate be a fair number if you're spending essentially no capital on pure gas?

That is probably a fair number, yes.

That's great.

Thank you so much.

Thank you.

Our next question comes from Blake Fernandez from Howard Weil.

Please go ahead.

Guys, good morning.

Thanks for taking my question.

I know Arjun just covered natural gas but I had the question in the past.

I know during weak gas pricing periods we've seen ConocoPhillips shut in production.

I was curious if we were going to hear something on that front this morning.

Is that in the cards here near term?

That's a good question.

Let me talk about gas production.

Our fourth quarter natural gas production in Canada and the Lower 48 was around 2.5 BCF a day.

So it's 400, maybe 410, MBOE per day.

As we look across that portfolio, there is probably two-thirds of it where the economics are really driven by liquids production and not natural gas prices.

So off the top, there is a portion of our portfolio which it's just not going to make sense to shut in.

So maybe 1.5 out of that 2.5 BCF of natural gas is really associated with liquids production.

Looking at, let's say, the remaining BCF a day, some of that we operate.

Some of that we don't operate and we have partners on a lot of that production as well.

And partners have different views about shut-ins with, I think, our partners generally not wanting to shut in natural gas and lose the cash flow associated with that.

So we are looking at the portion of our production that we control that decision entirely on, and think that we will have some shut-ins of natural gas going forward.

And it's going to be on the order of 100 million cubic feet a day, or something like 15,000 to 20,000 BOE per day, going forward.

And we will continue to watch that as the year goes on and we see how the natural gas markets develop.

That's great.

Very helpful.

Thank you.

And the last question I had for you, I was curious if you have any update on Venezuela.

Obviously one of your peers has had, I guess you could say, less than favorable arbitration results recently.

And I'm just curious if you have any comments you could make.

Yes, so you're referring to the Exxon ruling that they got in their ICC arbitration.

We chose not to pursue ICC arbitration and instead chose to pursue ICSID arbitration which is the World Bank process.

We've been through that hearing.

We're awaiting a ruling on that, which we expect could occur early this year even.

But we can't really be certain of the timing of that and we still feel very good about the case we have there.

Again, like we've said on the previous calls, with the initial ruling will be about will probably not result in a number, but will result in the parameters around which the number will be calculated.

And then we'll have a period that that will be done, and there'll be a period where appeals can also happen.

So we're still at least two or three years away from having something that we can collect.

Thank you so much.

Thank you.

Our next question comes from Faisel Khan from Citigroup.

Please go ahead.

Good morning.

Good morning, Faisel.

Just a quick question.

Going back to, you gave some numbers on the unconventional volumes in the US.

In the Bakken, you said you're doing about 15,000 barrels a day right now of equivalent production?

No, about 18,000.

18,000.

Okay.

And the Permian, you're doing?

Around 50,000.

Okay.

50.

5-0.

Okay, 50.

Got you.

That makes sense.

If you could contrast the Bakken to the Eagle Ford for a second here.

Because in the Eagle Ford you guys are running 16 rigs.

You're doing 50,000 barrels a day, going to 100,000.

In the Bakken, you're going from 10 to 15 rigs and you're only doing about 18,000.

Are the economics that much better in the Eagle Ford for you than the Bakken?

Or is there some sort of a ramp up period or well backlog that we're waiting for on the Bakken to come online?

It 's both of those things, Faisel.

The economics are better for us in the Eagle Ford than they are at the Bakken.

So that will have priority as we think about where we're allocating our capital.

We hold our leases in the Bakken on a long-term basis and don't need to do drilling there in order to maintain our acreage position.

So we're taking a very measured approach there.

We don't want to get ahead of infrastructure in the Bakken.

So you will see us continue to ramp up our activities there.

They're good strong return projects but it's not as strong as what we have in the Eagle Ford.

Okay.

And one question on the asset sale program.

You announced a Colonial sale.

You announced the COA sales.

Are there other logistics assets that you guys are looking to divest of?

Or are we still expected from here on out for most of the asset sales to be on the upstream side?

Yes, I think the upstream side.

We have marketing processes going on, on two refineries right now, as well.

Okay.

Understood.

Okay, great.

Thanks for the time.

I appreciate it.

Thank you.

Our next question comes from Doug Leggate from Bank of America/Merrill Lynch.

Please go ahead.

Hi, good morning, guys.

Good morning, Doug.

Just a couple of things.

I don't know if I missed this in your prepared remarks, Jeff, but what is the current status of Bohai Bay?

Are you back onstream?

Are you allowed to bring it back up?

And what is the production level, if you can help us out, first of all?

Production levels were down about 30,000, I think we said 33,000 a day, in the fourth quarter, from our previous level, which was our 45,000, 50,000 level.

15,000 to 20,000 barrels a day.

In the fourth quarter.

So we are working through a process of getting a revised field operating and development plan approved.

We are working that with the relevant agencies in China, where we hope to proceed with that as soon as we can.

But we can't really give you guidance on when exactly that's going to occur.

So Clayton, the numbers are currently about 15,000 to 20,000?

Is that still a good run rate, as we look forward for now?

Well, I think we could see that actually -- it will vary during 2012.

It could potentially be lower in the first quarter, and then improve as the year goes on.

It's as good as anything that we can give you right now.

Got it.

Thanks.

I hate to pound on the issue of shutting in gas production, but if I may just get some clarification there.

So you're suggesting you could maybe shut in about 100 million a day.

Is that operated or are there third-party production that you might have an interest in as well that might change that further?

A little bit of clarity of that will be appreciated, Jeff, please.

Just looking at the things that we operate, where we largely control the decision, I think --

And that don't have any liquids production.

They don't have significant liquids production, that don't have any operational concerns that you have to work through with shutting in.

I think this will be a subject that gets discussed quite a bit between partners all throughout the industry as we go forward and that could change if we have persistent low natural gas prices.

But our immediate guidance is that it looks like the numbers we said, something on the order of 15,000 to 20,000 BOE per day, or around 100 --

Up to that amount, I guess would be more --

Is what it looks like we will be moving on soon.

Okay.

Great and my final one, if I can squeeze one more in, is just a very quick update, please, on the infrastructure in the Eagle Ford.

I mean clearly, the ramp-up is continuing to go very, very strong.

So are you managing to keep up with that?

And I will leave it at that.

Thank you.

There are a couple of things that have happened in the fourth quarter.

Take away capacity has increased significantly in the fourth quarter over the third.

There's additional trucks.

There's a new condensate pipeline station which came online in late September.

As Jeff mentioned, we have some production curtailment due to infrastructure constraints as a result of well volumes.

But we're going to work with several companies to increase offtake capacity in the near and long term, and get transportation commitments set up for condensate and also increase or invest in increasing gas gathering and processing capacity.

Got it.

Thanks, guys.

I appreciate it.

All right, thanks, Doug.

Thank you.

Our next question comes from Paul Sankey from Deutsche Bank.

Please go ahead.

Hi, guys.

Good morning, Paul.

Clayton, could we just talk about the split?

I know you've been fairly specific about this, but I just wanted to reconfirm the dates of the intended split.

And I had a question which you may not frankly be able to answer but if the cash from operations you talked about, in 2011, I think it was $19.6 billion, could you separate the upstream and downstream components of that?

And perhaps spin forward your latest thoughts on versus, whether or not it's a 2011 cash flow, or whatever else you assume its cycle cash flow will be?

How the upstream and downstream companies in your latest thinking will be spending money and growing?

You mentioned the major Chemicals project in your prepared remarks, for example.

Any further updates on the split process would be great.

Thanks.

Sure, I think Jeff mentioned that you see the split occurring in the second quarter, as early as May.

I still think that is probably where we want to stay.

Yes, so we're progressing well in the things that you've seen some Form 10s filed and the revisions filed.

We're progressing well in our IRS.

So there's no major hurdles essentially, as far as you can tell?

No, I think things are progressing well to get into the second quarter and it could happen as early as May.

Right.

In terms of your 2011 cash flow question, we give you net income for R&M.

So we generated basically $20 billion of cash flow in 2011.

Broadly speaking, 80% of that, $16 billion or so came from upstream, and 20%, $4 billion came from downstream.

Yes, I've got $3.75 billion in net income, from R&M, and $850 million in DD&A.

Those are special items.

It's got some special items in it that you have to pull out but we've disclosed those.

And you also got on the cash flows, you've got of course the dividends that are coming out of the Chemicals and the Midstream business.

Right.

So I think upstream we will be spending its money predominantly on organic growth and we've talked a lot about that, what the projects are that are making that up, and that we anticipate that we'll be seeing 3% to 4% production growth.

With around $15 billion a year?

The spending?

$14 billion.

$14 billion.

Yes, $14 billion.

We announced a $15.5 billion capital program for 2012 and that's basically $14 billion upstream, and $1 billion, [$2.3 billion] downstream.

$200 million of other expenses, other expenditures.

So upstream we'll be executing that organic growth program.

The production increases and as we've equally significant, the changes are in our portfolio, which are going to drive increases in cash margins per BOE, are the growth drivers for upstream.

And then downstream will be?

Well, downstream there's probably $1 billion or so of capital that goes into the R&M business, as far as just keeping our refineries safe and making sure that we're doing the right things around our refining business.

The excess cash flow coming out of Phillips 66, we're talking internally about where that goes right now, whether that's into Chemicals or Midstream ventures.

Those are probably more likely candidates for the free cash flow that comes out of the business.

But we'll be able to provide you with more of our thinking about that before the split.

Before May, you will be coming back with a more specific set of go-forward assumptions?

Yes.

We're not going to have the typical analyst meeting that we have in March.

We've decided not to have.

But we do plan on meeting with you and with others in the financial community about what our plans are, both at Phillips 66 and with ConocoPhillips.

I think both Ryan and Greg will be available to the street, and we haven't scheduled that.

But think about a March or April time frame when we'll be out there and be able to fill you in a little bit more on what our thinking is.

Just one, I guess, the main issue in my mind, Clayton and Jeff, is the buyback.

And just can you remind us what happens with the buyback, once we split, how that works going forward?

We talked about asset sales of $5 billion to $10 billion, and that's pretty heavily weighted to the upstream side of the business, going forward.

And we said that share repurchases will generally track along with that, which says that we are continuing to buy shares currently, not at the same rates we were buying them last year.

So you'll see first quarter that there will be some buybacks that occur actually in the first quarter.

Then the pace of buybacks will depend upon the pace of our asset sales program and that really goes for ConocoPhillips, both before and after the split of the downstream company.

And the downstream company, as Clayton mentioned, we'll be out before the split talking more about how we're going to be allocating cash in that business.

The thinking, at least right now, around use of cash in Phillips 66, post-split, I would say we have prioritized the first $2 billion or so towards debt reduction versus share repurchase.

But those decisions have yet to be made.

That's good.

I think you've given me enough pieces to fit it together, which is very finely on asset sales.

Within Phillips 66, is there any update shall I think it was Alliance and Trainer that were publicly known to be out there?

I think we don't really have any updates.

I think data rooms are open.

Indicative bids are -- the deadline's coming up and we'll take a look at what comes in and then make our decisions going forward.

We don't have anything to add from what we've already talked about earlier on Trainer or Alliance.

But news shortly?

Maybe.

Okay.

Thanks.

Okay.

Thank you.

Our next question comes from Mark Gillman from The Benchmark Company.

Please go ahead.

Guys, good morning.

A couple of things, if I could.

Did the Endeavour sale of the UK assets close in the fourth quarter?

First quarter?

Was that --

No, that's still yet to close.

Did not close.

Did not close.

Anything going on with respect to the Vietnam sale?

There's been a lot of talk in the trades about bids that you've received, yet haven't heard much of anything in terms of discussions coming to a conclusion.

Yes, we'll probably going to give you the same answer we've been giving you on asset sales, as we just are working through a lot of different processes.

And it is not helpful to us to try to have a lot of information out until we get to a finishing point on those.

So I'm afraid there is not much we can update you on there.

Okay.

In terms of the Eagle Ford production numbers, Jeff and Clayton, that you talk about, still running about 70% liquids?

And do you expect, as the numbers build, to maintain that kind of liquids ratio?

I think we see more like 75% liquids.

And yes, that is our expectation going forward.

You think you will hold it at that level?

Yes.

Okay.

And of course, Mark, I think the classification for the liquids there are -- is it retrograde condensate, is the term that is used internally to describe those liquids.

I'm not sure what you mean by that, Clayton.

Well, you've just --

As opposed to NGL, you mean?

I mean, there's an NGL component but it is primarily condensate.

It is a high-value liquid.

Okay.

And in terms of the LIFO item, if I can call it that, in the fourth quarter, can I assume that is entirely US, that it's an after-tax figure and that it's included in your recorded and published refining margin?

Yes.

Yes, it is.

It is all US.

And it is after-tax and it is included.

And one final one for me.

There's been a fair amount of talk, this isn't really asset-sales oriented but I've seen a fair amount of talk that you may be seeking partners either for your Eagle Ford activities and/or your Canadian oil sands outside of the partnerships with Cenovus.

Can you comment on the veracity of that?

We intend to pursue Eagle Ford as 100% development going forward.

So I hadn't heard that one, but we can tell that you there is nothing behind that.

We are investigating options for our oil sands properties outside of the Foster Creek Christina Lake joint venture.

We think there's quite a bit of interest in properties like that.

So we'll do some things to find out how the market would value those and make our decisions going forward, based on what we find out.

But we would intend to maintain interest in the properties outside of FCCL.

It's just a question of whether there would be valuable to bring in a partner to develop those.

And Jeff, that would include Surmont?

Yes, it would include Surmont.

Okay, final one for me.

Excluding the WRB partnership, give me a rough idea of the WTI reference price crude that you ran in the fourth quarter, taking the partnership out of the equation.

This is fourth quarter WTI?

The fourth quarter WTI reference ex-WRB.

Ex Borger and Wood River.

I think it is going to be around 200,000 barrels a day but let us check our numbers.

Okay.

Including those two, it's somewhere between 450,000 and 500,000.

So I just have to back out what Borger and Wood River represent.

Okay.

Well that's pretty much 100% on those two, isn't it?

WTI reference, if you include WCS, WTI reference crude?

Yes, and we have 50% of Borger and50% of Wood River, so that's what?

That is 350,000, 250,000?

Yes, something like that.

I mean, the math seems to work.

It is 200,000 to 250,000, something like that.

Okay.

That's good.

Thanks.

Thank you.

Our next question comes from Paul Cheng from Barclays Capital.

Please go ahead.

Hi, good morning.

Several quick questions.

Jeff, you say $180 million on the inventory pretax number.

Should we just assume like 35% tax rate?

That's probably a good assumption, yes.

Okay.

In the Bohai Bay, the press release is talking about a settlement with the compensation funds.

If that settled all the losses out there, or are there other things that are still pending that we should be aware?

So the settlement is for the fisheries that were potentially impacted by the spill, which is the primary issue that we are dealing with.

So that was probably about all we could say at that point.

We don't know if there will be other things beyond that.

How about from the regulator.

I think they have fined you guys some small amount?

I presume that based on the Chinese note, that is really -- major potential fine that we should expect from the regulator, right?

I think, Paul, we can really say at this point is that we think that the settlement we just announced last night is an important step forward, and resolves the most pressing issues that are out there, and we're just going to need to move forward with the process, with the authorities there.

And there's not a lot else we can comment on at this point in time.

Okay.

Jeff, what's this Libyan production right now, for you guys?

Libyan production -- It is around 20,000 barrels a day.

Net to you?

Net to us, that's right.

So that's our share of the Waha concession.

So I think we have 16 --

16 2/3 Waha.

Jeff, and looking at your financial statement, have you about $1.2 billion, $1.3 billion after deferred tax cash contribution in 2011.

If that is all contributed from the IDC deduction, in the US or related to other things also?

No, it really doesn't -- it is primarily related to timing differences between tax depreciation and financial depreciation.

So that is not related to IDC?

You know, IDC could be a small portion of that number, but it is not a big number for us.

It is a small portion.

And once you spin off the treatment for the IDC deduction, it is going to change.

Currently are you deducting, what, 50% or 75%.

Paul, I would have to get back to you.

It is not a very high percentage of that number.

Because of the category that we fall in.

It is different rules for different size producers.

Right.

And then even going forward, it's a complex set of rules that will determine which category you fall into.

And we could be still considered an integrated by some of those measures, even going forward because we have things like fractionation capacity and some of our processing up on the North Slope.

So it is not as clear-cut as just saying that we move from one category to another.

Right.

So you currently, based on your best guess, is that you may not change that much full year?

I'm not sure that we see that that's a significant change for us.

That's correct.

I see.

And Clayton, is it possible that if you can share that what is the benefit in 2011 for you guys?

From the cash flow standpoint, related to the IDC deduction?

We don't know that number off the top of our heads.

Right.

So I mean, at some point, when you find it, can you just email me?

We can work that up.

Great.

Final one.

The APLNG Sinopec interest increase to 25%.

Last time, when they opt in that, that was way down.

Should we assume that as a result that the carrying costs for you guys is already now at a level their increase in the interest in here is not going to change your carrying value?

Yes, so we'll be working that as we go forward.

It depends some exactly when the whole transaction ends up closing.

We will have an additional write-down on APLNG when that transaction closes.

It won't be of the same magnitude of what we had before.

And right now we'd say it's in the neighborhood of $100 million.

$100 million?

Right.

Okay.

Very good.

Thank you.

Thank you.

Our next question comes from Phillip Weiss from Argus research.

Please go ahead.

Good morning.

Good morning Phil.

Just a couple quick questions.

North America acreage acquisitions that you mentioned, do you have any color on how much or where those were?

We're reluctant to just give exactly what was where.

But it is in the areas we mentioned, which is the Duvernay, the Canol, Avalon, Wolfcamp, Niobrara, and some other areas.

It was probably two-thirds Canadian, one-third Lower 48 acreage and it was all targeting plays which we believe are liquids-rich plays and not gas plays.

There were some public disclosures on the UT license round at Wolfcamp, but we haven't given a lot of detail yet because we're not finished buying.

Okay.

The exploration expense, any dry hole charges you can identify in the quarter?

We had what, $141 million dry hole expense in E&P for the quarter.

I think that's the number.

I think there was a -- well, I just don't -- we can get back to you on that one, Phil.

I don't know where those were but obviously it was higher in the fourth quarter than it was in the rest of the year.

But we can come back and let you know where those dry hole expenses took place.

Okay.

And then last one.

There's just something I'm a little bit confused about.

When I look at the financial statement information that you gave, it showed impairments in the fourth quarter of $304 million.

But then when you have the special item, the impairments were like $695 million and I didn't understand why that was.

So are you looking at page 3 on the special items page on the supplement?

Yes.

And the question is what E&P impairments?

Well, if I look at the consolidated income statement, it shows impairments of $304 million.

And then if you look at page 3, just for international E&P impairments, it is $585 million and for US, it is $44 million.

So that is $629 million.

I think the total number when you did your whole reconciliation was $695 million.

Let me come back to you on that one.

I will give you a call this afternoon.

That's fine.

I'm not sure why we put in that $304 million number on the face of the income statement.

Okay.

That's all I had.

Thanks.

Okay.

Thanks.

Thank you.

Our next question comes from Daniellea Almeda from Jefferies.

Please go ahead.

Hi, it's Ian Reid, actually, from Jefferies over in London.

Sorry about that.

She's a lot better looking than me, though.

Sorry?

That's not saying very much actually.

Okay, okay.

Just on the oil sands.

You can say why at Surmont you're looking to reduce your interest, rather than the FCCL joint venture?

Is it just because the fact it's a joint venture and it's tied up with the refining?

Or is there a specific reason why it's Surmont and the other assets rather than that?

I think we look at the Surmont project and our remaining assets and combined with the FCCL and thinking of the size of oil sands in our portfolio, and also the values that people attribute to properties that are out in the marketplace right now, and think it makes sense to just find out what value the market will ascribe to that.

It's most straightforward to do that on the Surmont project But it is not just Surmont.

It's the Thornbury and Clyden and Saleski acreage that we have as well that we would consider doing something with as a package.

And FCCL, I would think we would probably look at more a part of our portfolio and good economics and something that is going to generate growth for us over a longer period of time.

The returns, I think most people look at FCCL as probably the premiere oil sands assets.

And so, it could be that TCS and Surmont won't be able to generate the types of returns that FCCL can.

Okay.

Sounds great.

I wonder whether your thoughts have changed or progressed in terms of LNG exports.

Now you've seen these deals signed up on the Gulf Coast at the Shania facilities which they intend to build.

Is that something you would look at again or put more emphasis on, given the substantial amounts of US gas that you're producing or will be producing?

I think it's something we are going to continue to study.

And it is really not just thinking about it from the perspective of Lower 48 natural gas production, but as we think about what long-term alternatives are for Canadian gas production, and importantly, as we think about what alternatives could be for development of the North Slope gas in Alaska.

Those are all things that we'll be investigating whether liquefaction and export of natural gas makes sense going forward.

Okay.

Thanks, Jeff.

And last one.

Just coming back to this $180 million of inventory liquidation, can we assume that that is all associated with the shutdown of Trainer and the associated tankage and pipes, et cetera?

A large part of it was Trainer.

It was all things we had inventory in the Seaway Products pipeline, for example.

We sold some terminals during the year that had inventory as well.

So Trainer made it, was the largest single component of that but it was not all related to Trainer.

So it wasn't kind of an inventory price adjustment, there was a real liquidation, an exit from that?

Yes.

We reduced our inventories across the system by about 10 million barrels during the year.

Great.

Thanks for your help.

Thank you.

Our final question comes from Evan Calio from Morgan Stanley.

Please go ahead.

Good afternoon, guys.

Hello, Evan.

A lot has been cover here so just a couple of questions on the quarter.

Just a follow-up on the last question on the inventory liquidation.

Is there any quantification on what is coming back, what is year end related that we should see back in 1Q?

In terms of building inventory?

That's right.

Probably not.

You're saying what our inventory levels will return to?

That's right.

If there was anything -- I know there's some that's inventory liquidation but if some was into taking inventories down into year end and something that we can come back in 1Q and offset.

We have inventories related to our system and then we have some inventories that we take on as more of a system optimization, trading type operations.

We'll bring some of those back on in the first quarter.

But I don't think we have the number that we can give you as guidance right now.

Okay.

On the change in the corporate charge, $151 million, can you deconstruct that a little bit just so again, the same, to understand better what is recurring?

I presume the FOREX element would be a nonrecurring change.

Yes, FOREX is the nonrecurring change.

And you can see in our supplemental information that that was $45 million to $50 million of that difference.

In our comments, you probably picked up, we were saying corporate costs, we would say going forward are more of $1 billion per year run rate.

And more a $250 million a quarter.

I think our previous guidance was more like $275 million, a quarter.

So interest costs lower being a driver of that.

Capitalized interest.

And then capitalized interest.

Capitalized interest was a little bit higher than we initially anticipated it was going to be.

I think those are the major drivers of it.

So FOREX is a big part of that, which is going to be changed from quarter to quarter.

Okay.

That's great.

Angola block payment, was that included in 4Q?

No, it's a first quarter 2012 item.

Okay.

And then you mentioned Chevron Phillips.

You guys were conducting the study for the 3 billion-ton Gulf Coast, I think, cracker.

What are the key dates in 2012 in that project?

When will we get more specifics on the costs and FID date, timing, et cetera?

So I'm not sure exactly when we go to FID on it.

Well, to answer your question, I guess we'll give you more information on that in late March or early April when we come out and start talking about the sources of growth for Phillips 66.

Okay.

Great.

And just lastly, just to follow up on the buyback.

Does your buyback guidance in '12 contemplate the $5.8 billion distribution related to the leveraging on Phillips 66?

Because that would impact the kind of timing of available cash.

I don't think the intent to use payment for Phillips 66 back for debt reduction primarily.

Yes, primarily so we're talking about --

Oh, I got you.

At the Conoco level.

Yes, so we will have roughly $6 billion of proceeds come in from the distribution as we contemplated it now, and we'll probably use -- we've targeted taking our Conoco Phillips debt level down to around $18 billion.

We ended the year at $22.5 billion so we're going to use about $4.5 billion of that reduced debt.

So it will be some that goes into the cash from that distribution.

But the thinking on share repurchases really, Evan, think about share repurchase being funded by asset sales.

That's really what it is going to fund that activity.

Right.

And then based on at least the bid dates, you're hopeful that the two refining asset sales would be received prior to distribution?

No, I don't think that we would give you that impression.

Okay.

There will be things to work through on refinery sales that will probably take those post.

Got it.

Appreciate it, guys.

Okay, thanks.

So I guess that was the last question.

Kim, appreciate you lining those up for us.

And appreciate everybody participating in the call.

You can find our material again on our website.

I look forward to talking with you in the near future.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.